Methods for reducing transmix production on petroleum pipelines

ABSTRACT

Automated methods and systems for diverting transmix from a petroleum pipeline are provided to reduce the overall production of transmix on the pipeline, based on pre-defined programmed cut-points associated with the various subtypes of hydrocarbon carried on the pipeline.

FIELD OF INVENTION

The present invention relates to pipeline batch shipments of products ofdifferent specifications, and the off-specification product created attheir interface (“transmix”). Specifically, the invention relates tomethods for reducing the volume of transmix created when shippingproducts of different specifications on a petroleum pipeline.

BACKGROUND OF INVENTION

Transmix is created when products of different specifications areshipped sequentially on a pipeline. The pipeline operator might ship avolume of distillate (aviation turbine fuel or Ultra Low Sulfur Diesel,etc.) followed by a volume of gasoline intended for automobiles. Whenthese two products meet in the pipeline at an interface, a quantity ofoff-specification product referred to as “transmix” is created. There isno mechanical buffer used to keep the two products from mixing andbecoming contaminated at this interface. The transmix does not meetapproved specifications for most fuel products and cannot be used incommerce.

In the United States, pipelines ship motor gasoline, diesel fuel, jetfuel, naphtha's, LPG, diluent, butane, propane, pentane, and otherhydrocarbon products on the same clean pipeline. Both refineries andpetroleum terminals ship on these common carrier pipelines, in varyingsizes or batches. A batch is the volume of a product shipped on thepipeline meeting a pre-defined set of product specifications. Thepipeline companies and various regulatory authorities publish productspecifications that shippers on the pipeline are required to meet beforeintroducing their products into the pipeline. The pipeline company mustensure that the products it eventually releases into commerce meet thesespecifications. The shippers provide a certified analysis of theproducts to the pipeline company to verify the products meet the minimumor maximum specifications published by the pipeline company.

All multi-product pipelines create a volume of transmix that is notmarketable for use in commerce. This transmix may be composed, forexample, of previously certified gasoline (including previouslycertified gasoline blend-stocks that become gasoline solely upon theaddition of an oxygenate), distillate fuel (such as diesel, aviationfuel, kerosene and heating oils), and other certified product types. Theproblem is particularly acute when diluents, ultra-low sulfur diesel,aviation turbine fuel, and gasoline are shipped next to each other.

The United States Environmental Protection Agency (“EPA”) definesinterface and transmix in regulations at 40 C.F.R. 80.84, and prescribesprocesses that pipeline operators must follow to dispose of transmix.This transmix must typically be re-processed before it can once again bemarketed in commerce. The value of transmix is thus lower than thehydrocarbon products from which the transmix derives, and it is in thecommercial interest of pipelines and pipeline shippers to minimize thistransmix.

Presently, pipeline operators monitor the specific gravity, flash point,haze and color of batched products to determine when transmix is presentand when on-specification products are in the pipeline. Based on theirstandard operating procedures, the pipeline operator will direct thetransmix to a transmix storage tank when it reaches a particularjuncture on the pipeline, where it can be stored for eventual shipmentto a transmix processing plant. Once the transmix has been completelydiverted from the pipeline, and on-specification products are once againflowing past this juncture, the operator will resume the product flowthrough the pipeline and direct the on-specification product to othertanks in the tank farm for eventual distribution to customers and incommerce. The more time it takes for the pipeline to make the interfacecut, the more transmix that is created. Again, it is in the bestinterest of the pipeline company to create the smallest amount oftransmix as possible.

Accordingly, it is an object of the present invention to reduce thevolume of transmix created on petroleum pipelines, and to maximize theretention of on-specification products for commercial distribution.

It is another object to provide methods of managing transmix thatminimize the volume of transmix production during pipelinetransportation while ensuring that on-specification products remainwithin their prescribed specifications.

A still further object is to automate the process of transmix diversion,so that transmix is diverted from the pipeline using consistent numericcriteria, and reducing the need for guesswork and significant humanintervention.

SUMMARY OF THE INVENTION

After significant work and experimentation, the inventors have developedmethods for tightly controlling the production of transmix on apetroleum pipeline, and thereby reducing the production of thisoff-specification product. The methods are performed at a juncture on apetroleum transmission pipe, by diverting the hydrocarbon flow into atransmix pipe when transmix starts flowing through the juncture, andresuming the flow through the transmission pipe when an on-specificationcommercial grade hydrocarbon subtype once again is flowing through thejuncture. In the methods of the invention, each sub-type of hydrocarbonthat generates transmix is assigned one or more specifications or“cut-points” that define the hydrocarbon subtype and distinguish it fromother subtypes flowing through the pipeline. When the physicalproperties of the flow reach one or more of these pre-specifiedcut-points, the flow is diverted to the transmix pipe. When the physicalproperties reach the cut-points for the succeeding hydrocarbon subtype,the flow is resumed through the transmission pipe.

Thus, in a first principal embodiment the invention provides anautomated method for reducing transmix production on a pipelinecomprising: (a) providing a flow of hydrocarbon in a transmission pipecomprising first and second hydrocarbon subtypes in sequence separatedby transmix; (b) providing a transmix pipe in fluid communication withthe transmission pipe separated from the transmission pipe by a transmixvalve under the control of a central processing unit; (c) repeatedlyanalyzing the flow for physical property measurements; (d) comparing, inthe central processing unit, the measurements to a first subtypecut-point, and diverting the flow to a transmix pipe when themeasurements reach the first subtype cut-point; and (e) resuming theflow through the transmission pipe when the measurements reach a secondsubtype cut-point.

A second principal embodiment is premised on the fact that mosthydrocarbon batches are defined by a plurality of physical properties orspecifications, and that all of the specifications must be satisfied tohave a commercially viable hydrocarbon subtype. Thus, while the flowshould be diverted to the transmix pipe upon reaching the limits of onlyone specification or cut-point, it should only be resumed once all ofthe specifications or cut-points of the succeeding batch are satisfied.Therefore, in a second principal embodiment the invention provides anautomated method for reducing transmix production on a pipelinecomprising: (a) providing a flow of hydrocarbon in a transmission pipecomprising first and second hydrocarbon subtypes in sequence separatedby transmix; (b) providing a transmix pipe in fluid communication withthe transmission pipe separated from the transmission pipe by a transmixvalve under the control of a central processing unit; (c) providingfirst and second cut-points for different physical properties of thefirst subtype; (d) providing first and second cut-points for differentphysical properties of the second subtype; (e) repeatedly analyzing theflow for physical property measurements; (f) comparing, in the centralprocessing unit, the physical property measurements to the first andsecond cut-points of the first subtype, and diverting the flow to atransmix pipe when the measurements reach the first or second cut-pointof the first subtype; (g) resuming the flow through the transmissionpipe when the measurements reach the first and second cut-points for thesecond subtype.

A third principal embodiment is premised on the use of batch sequenceinformation to determine what hydrocarbon subtypes are flowing throughthe transmix juncture, to determine which set of cut-points to applywhen deciding whether to divert the flow to the transmix pipe, and whichset of cut-points to apply when deciding whether to resume the flowthrough the transmission pipe. Thus, in a third principal embodiment theinvention provides an automated method for reducing transmix productionon a pipeline comprising: (a) providing a flow of hydrocarbon in atransmission pipe comprising first and second hydrocarbon subtypes insequence separated by transmix; (b) providing a transmix pipe in fluidcommunication with the transmission pipe separated from the transmissionpipe by a transmix valve under the control of a central processing unit;(c) receiving a subtype sequence identification signal at the centralprocessing unit identifying the first and second subtypes and thelocation of the first and second subtypes in the transmission pipe; (d)receiving physical property measurements of the flow passing through thevalve at the central processing unit; (e) executing programmed logic inthe central processing unit to: (i) determine the subtype flowingthrough the valve based on the subtype sequence identification signal;(ii) when the first subtype is flowing through the valve, accessing adataset comprising a first cut-point for the first subtype and comparingthe physical property measurements to the first cut-point of the firstsubtype; (iii) diverting the flow to the transmix pipe when a physicalproperty measurement reaches the first cut-point of the first subtype;(iv) accessing a dataset comprising the first cut-point of the secondsubtype, comparing the physical property measurements to the firstcut-point of the second subtype; and (v) resuming the flow through thetransmission pipe when a physical property measurement reaches the firstcut-point of the second subtype.

Still further embodiments related to the automated systems used to carryout the processes of the current invention. Thus, in a fourth principalembodiment the invention provides a system for reducing transmixproduction on a pipeline comprising: (a) a transmission pipe comprisinga flow of hydrocarbon subtypes in sequence comprising a first subtypeand a second subtype separated by transmix; (b) a transmix pipe in fluidcommunication with the transmission pipe, separated from thetransmission pipe by an automated diversion valve; (c) a firstanalytical unit in sensory communication with the transmission pipe, forgenerating measurements of a physical property of the flow; (d) acentral processing unit in sensory communication with the firstanalytical unit and the transmix valve, logically programmed to receivethe measurements from the analytical unit, compare the measurements tofirst subtype and second subtype cut-points, signal the diversion valveto turn toward the transmix pipe when the measurements reach the firstsubtype cut-point, and signal the diversion valve to turn the flowtoward the transmission pipe when the measurements reach the secondsubtype cut-point.

Additional advantages of the invention are set forth in part in thedescription that follows, and in part will be obvious from thedescription, or may be learned by practice of the invention. Theadvantages of the invention will be realized and attained by means ofthe elements and combinations particularly pointed out in the appendedclaims. It is to be understood that both the foregoing generaldescription and the following detailed description are exemplary andexplanatory only and are not restrictive of the invention, as claimed.

BRIEF DESCRIPTION OF THE DRAWINGS

A better understanding of the present invention can be obtained when thefollowing detailed description of the disclosed embodiments isconsidered in conjunction with the following drawings, in which:

FIG. 1 is a functional block diagram illustrating the types andlocations of exemplary equipment used to practice the current invention.

FIG. 2 is a process flow diagram illustrating a preferred method ofpracticing the invention.

FIGS. 3-22 plot sulfur concentrations of consecutive batches ofhydrocarbon subtypes in a pipeline flow simulated at laboratory scale asdescribed in Example 2.

DETAILED DESCRIPTION Definitions and Use of Terms

Throughout this application, various publications are referenced. Thedisclosures of these publications in their entireties are herebyincorporated by reference into this application in order to more fullydescribe the state of the art to which this invention pertains. Thereferences disclosed are also individually and specifically incorporatedby reference herein for the material contained in them that is discussedin the sentence in which the reference is relied upon.

As used in the specification and claims, the singular forms a, an, andthe include plural references unless the context clearly dictatesotherwise. For example, the term “a cut-point” refers to one or morecut-points for use in the presently disclosed methods and systems. “Ahydrocarbon” includes mixtures of two or more such hydrocarbons, and thelike. The word “or” or like terms as used herein means any one member ofa particular list and also includes any combination of members of thatlist.

When used herein the term “about” will compensate for variabilityallowed for in the petroleum industry and inherent in hydrocarbonproducts. In one embodiment the term allows for any variation within 5%of the recited specification or cut-point. When percentages,concentrations or other units of measure are given herein, it will beunderstood that the units of measure are weight percent unless otherwisestated to the contrary.

When ranges are expressed herein by specifying alternative upper andlower limits of the range, it will be understood that the endpoints canbe combined in any manner that is mathematically feasible. Thus, forexample, a range of from 50 or 80 to 100 or 70 can alternatively beexpressed as a series of ranges of from 50 to 100, from 50 to 70, andfrom 80 to 100. When a series of upper bounds and lower bounds arerelated using the phase “and” or “or”, it will be understood that theupper bounds can be unlimited by the lower bonds or combined with thelower bounds, and vice versa. Thus, for example, a range of greater than40% and/or less than 80% includes ranges of greater than 40%, less than80%, and greater than 40% but less than 80%.

“ASTM” refers to the American Society for Testing and Materials.Whenever a petroleum subtype is referenced herein, it will be understoodthat the subtype can be defined by specifications and testing methodsprescribed by ASTM in its various publications. Thus, for example,aviation turbine fuel can be defined with reference to ASTM 1655-15de1,and diesel fuels can be defined with reference to ASTM D975 - 15c.Unless otherwise indicated, when reference is made to an ASTM standardherein, it is made in reference to the ASTM standard in effect on Jun.1, 2016, and the ASTM standard is incorporated herein by reference.

“Programmable Logic Controller” or “PLC” when used herein, refers to adata processing system which can receive, retrieve, store, process, andoutput data. The PLC processes data which has been captured and encodedin a format recognizable by the data processing system. The PLCcommunicates with other PLC(s), information database(s), component(s),system(s) and device(s) encompassed by the methods and systems of thepresent invention.

“Informational database,” when used herein, refers to a data storingsystem which can receive, store and output data. The informationaldatabase communicates with or is accessible to other informationaldatabase(s), PLC(s), component(s), system(s) and device(s) encompassedby the methods and systems of the present invention.

When data or a signal is referred to herein as being transmitted betweentwo PLCs or an PLC and an information database, or other words of likeimport such as “communicated” or “delivered” are used, it will beunderstood that the transmission can be indirect, as when anintermediate PLC receives and forwards the signal or data. It will alsobe understood that the transmission can be passive or active.

The invention is defined in terms of principal embodiments andsubembodiments. When an embodiment or subembodiment other than theprincipal embodiment is discussed herein, it will be understood that theembodiment or subembodiment can be applied to further limit any three ofthe principal embodiments. It will also be understood that the elementsand subembodiments can be combined to create another distinct embodimentencompassed by the present invention.

When an element of a process or thing is defined by reference to one ormore examples, components, properties or characteristics, it will beunderstood that any one or combination of those components, propertiesor characteristics can also be used to define the subject matter atissue. This might occur, for example, when specific examples of anelement are recited in a claim (as in a Markush grouping), or an elementis defined by a plurality of characteristics. Thus, for example, if aclaimed system comprises element A defined by elements A1, A2 and A3, incombination with element B defined by elements B1, B2 and B3, theinvention will also be understood to cover a system defined by element Awithout element B, a system in which element A is defined by elements A1and A2 in combination with element B defined by elements B2 and B3, etc.

Discussion of Principal Embodiments

The invention can be defined based on several principal embodimentswhich can be combined in any manner physically and mathematicallypossible to create additional principal embodiments. In a firstprincipal embodiment the invention provides an automated method forreducing transmix production on a pipeline comprising: (a) providing aflow of hydrocarbon in a transmission pipe comprising first and secondhydrocarbon subtypes in sequence separated by transmix; (b) providing atransmix pipe in fluid communication with the transmission pipeseparated from the transmission pipe by a transmix valve under thecontrol of a central processing unit; (c) repeatedly analyzing the flowfor physical property measurements; (d) comparing, in the centralprocessing unit, the measurements to a first subtype cut-point, anddiverting the flow to a transmix pipe when the measurements reach thefirst subtype cut-point; and (e) resuming the flow through thetransmission pipe when the measurements reach a second subtypecut-point.

In a second principal embodiment the invention provides an automatedmethod for reducing transmix production on a pipeline comprising: (a)providing a flow of hydrocarbon in a transmission pipe comprising firstand second hydrocarbon subtypes in sequence separated by transmix; (b)providing a transmix pipe in fluid communication with the transmissionpipe separated from the transmission pipe by a transmix valve under thecontrol of a central processing unit; (c) providing first and secondcut-points for different physical properties of the first subtype; (d)providing first and second cut-points for different physical propertiesof the second subtype; (e) repeatedly analyzing the flow for physicalproperty measurements; (f) comparing, in the central processing unit,the physical property measurements to the first and second cut-points ofthe first subtype, and diverting the flow to a transmix pipe when themeasurements reach the first or second cut-point of the first subtype;(g) resuming the flow through the transmission pipe when themeasurements reach the first and second cut-points for the secondsubtype.

In a third principal embodiment the invention provides an automatedmethod for reducing transmix production on a pipeline comprising: (a)providing a flow of hydrocarbon in a transmission pipe comprising firstand second hydrocarbon subtypes in sequence separated by transmix; (b)providing a transmix pipe in fluid communication with the transmissionpipe separated from the transmission pipe by a transmix valve under thecontrol of a central processing unit; (c) receiving a subtype sequenceidentification signal at the central processing unit identifying thefirst and second subtypes and the location of the first and secondsubtypes in the transmission pipe; (d) receiving physical propertymeasurements of the flow passing through the valve at the centralprocessing unit; (e) executing programmed logic in the centralprocessing unit to: (i) determine the subtype flowing through the valvebased on the subtype sequence identification signal; (ii) when the firstsubtype is flowing through the valve, accessing a dataset comprising afirst cut-point for the first subtype and comparing the physicalproperty measurements to the first cut-point of the first subtype; (iii)diverting the flow to the transmix pipe when a physical propertymeasurement reaches the first cut-point of the first subtype; (iv)accessing a dataset comprising the first cut-point of the secondsubtype, comparing the physical property measurements to the firstcut-point of the second subtype; and (v) resuming the flow through thetransmission pipe when a physical property measurement reaches the firstcut-point of the second subtype.

In a fourth principal embodiment the invention provides a system forreducing transmix production on a pipeline comprising: (a) atransmission pipe comprising a flow of hydrocarbon subtypes in sequencecomprising a first subtype and a second subtype separated by transmix;(b) a transmix pipe in fluid communication with the transmission pipe,separated from the transmission pipe by an automated diversion valve;(c) a first analytical unit in sensory communication with thetransmission pipe, for generating measurements of a physical property ofthe flow; (d) a central processing unit in sensory communication withthe first analytical unit and the transmix valve, logically programmedto receive the measurements from the analytical unit, compare themeasurements to first subtype and second subtype cut-points, signal thediversion valve to turn toward the transmix pipe when the measurementsreach the first subtype cut-point, and signal the diversion valve toturn the flow toward the transmission pipe when the measurements reachthe second subtype cut-point.

Discussion of Subembodiments

The invention can further be understood with reference to varioussubembodiments which can modify any of the principal embodiments. Thesesubembodiments can be combined in any manner that is both mathematicallyand physically possible to create additional subembodiments, which inturn can modify any of the principal embodiments.

As discussed above, the invention uses cut-points associated withindividual hydrocarbon subtypes to determine when to divert transmixfrom a transmission pipe, and when to resume the flow of hydrocarbonthrough the transmission pipe. One, two, three, four, or any number ofcut-points can be used to define a hydrocarbon subtype or batch, butthere will typically be at least two or three cut-points.

In any of the embodiments of the present invention, only one of thecut-points typically needs to be satisfied before diverting the flow tothe transmix pipe, whereas all of the cut-points must be satisfied toresume the flow through the transmission pipe. Thus, any of theembodiments can further be defined by (a) providing a second cut-pointfor the first subtype for a different physical property than the firstcut-point; (b) providing a second cut-point for the second subtype for adifferent physical property than the first cut-point; (c) diverting theflow to a transmix pipe when the flow reaches the first or secondcut-point of the first subtype; but (d) resuming the flow through thetransmission pipe when the flow reaches the first and second cut-pointsof the second subtype.

The invention also preferably employs batch information to determine thesubtype of hydrocarbon flowing past a juncture in the transmission pipe,and the subtype to expect once the first subtype and transmix havepassed the juncture. The subtype will typically be derived from batchinformation or a “cycle schedule” that includes the rate of flow throughthe transmission pipe, the time required for a hydrocarbon batch to flowpast a particular juncture, and the distance of the batch from thejuncture. Alternatively, the batch information can include the timeswhen batches of hydrocarbon flowing through the pipeline will start andend passing a particular juncture.

This batch information is typically processed by a PLC to determine thehydrocarbon subtype flowing past a juncture, compare the physicalproperty measurements at the juncture to one or more cut-pointsassociated with the subtype, divert the flow to the transmix pipe whenone or more of the cut-points is reached, compare the physical propertymeasurements at the juncture to one or more cut-points associated withthe succeeding subtype, and resume the flow through the transmissionpipe once the flow reaches the cut-points of the succeeding subtype.

The methods can also be practiced when the subtypes are defined by threeor more cut-points. Thus, the methods may further comprise (a) providinga third cut-point for the first subtype for a different physicalproperty than the first and second cut-points; (b) providing a thirdcut-point for the second subtype for a different physical property thanthe first and second cut-points; (c) analyzing the flow for physicalproperty measurements of the first, second and third cut-points of thefirst and second subtypes; (d) diverting the flow to a transmix pipewhen the physical property measurements reach either the the first orsecond or third cut-point of the first sub-type; but (e) resuming theflow through the transmission only when the physical propertymeasurements reach all of the first and second and third cut-points ofthe second subtype.

As noted above, the methods of the present invention can be practiced inpipelines that carry multiple subtypes of hydrocarbon, and whichgenerate transmix at multiple interfaces of these varying subtypes.Thus, the invention can also be practiced when the flow of hydrocarbonfurther comprises a third subtype in sequence, further comprising: (a)providing a first cut-point for the third subtype; (b) analyzing theflow for physical property measurements of the first cut-point of thesecond subtype and the first cut-point of the third subtype; (c)diverting the flow to the transmix pipe when physical propertymeasurement reaches the first cut-point of the second subtype; and (d)resuming the flow through the transmission pipe when the measurementsreach the third subtype first cut-point and third subtype secondcut-point.

The invention can be practiced whenever transmix is generated betweenhydrocarbons of different subtypes, as long as the subtypes areadequately characterized by a discreet set of physical properties, andthe physical properties can be analyzed fast enough to distinguish thesubtypes before the transmix has completely passed the analysis point.Thus, for example, the invention can be practiced when the flowcomprises three, four, five or more hydrocarbon subtypes selected fromconventional gasoline, reformulated gasoline, diesel fuel, ultra-lowsulfur diesel, biodiesel fuel, aviation turbine fuel, heating oil,kerosene, RBOB, PBOB, CBOB, subgrade gasoline, diluent, propane, pentaneand butane. In a preferred embodiment, however, the invention is used toreduce transmix generated at the interface of two hydrocarbon subtypesselected from aviation turbine fuel, ultra-low sulfur diesel fuel, amotor gasoline, and a diluent.

Various physical properties can be used for the cut-points of thepresent invention. They can be defined in terms of ranges for aparticular hydrocarbon subtype, maximum allowable limits, or minimumallowable limits. Thus, when the cut-point defines a ceiling on aphysical property, whether in a range or maximum allowable limit,“reaching a cut-point” will occur when a physical property correspondingto the cut-point is greater than or equal to the cut-point. When acut-point defines a floor on a physical property, whether in a range ora minimum allowable limit, “reaching a cut-point” will occur when aphysical property corresponding to the cut-point is less than or equalto the cut-point.

It will also be understood that a cut-point is not reached until two ormore sequential measurements for the cut-point have been satisfied.Thus, in any of the embodiments of this invention, reaching a cut-pointwill occur when two or more consecutive analyses of the flow yield aphysical property measurement greater than or equal to the cut-pointwhen the cut-point defines a ceiling, and a physical propertymeasurement less than or equal to the cut-point when the cut-pointdefines a floor.

Preferred cut-points are physical property values selected from sulfurcontent, specific gravity, API gravity, haze, color and flashpoint, andcombinations thereof. A preferred combination of physical properties tomonitor is sulfur content, gravity (either or both of specific gravityand API gravity), and flashpoint. One or more of these physicalproperties can be monitored, depending on the cut-points associated withthe batch flowing past the juncture, preferably at a frequency of atleast every minute, 30 seconds, 15 seconds, or 10 seconds. The flow ofhydrocarbon is preferably analyzed by: (a) withdrawing a sample of theflow of hydrocarbon from the transmission pipe; (b) transmitting thesample to an analyzing unit; and (c) either returning the sample to thetransmission pipe, or transmitting the sample to a storage unit. Aparticularly suitable sulfur analyzer is the Sindie® 6010 On-line MWDXRF Analyzer by XOS® products. Flash point is suitably analyzed by aFDA-5™ Flash Point Analyzer by Bartec Top Holding GmbH, and haze issuitably monitored by the Haze Tracker' from Automated PipelineInstruments (APLI).

The invention is particularly well adapted to distinguishing subtypesbased on the concentration of sulfur in the subtypes, when sulfurconcentration is a requirement for the sub-type. Thus, for example, inanother embodiment the first subtype is a high sulfur subtype and thesecond subtype is a low sulfur subtype, and the second subtype firstcut-point comprises a sulfur content value. In still another embodimentthe first subtype is a low sulfur subtype and the second subtype is ahigh sulfur subtype, and the first subtype first cut-point is a sulfurcontent value.

It will be understood that any of the features of the methods of thepresent invention apply equally to the systems of the present invention,and vice versa. However, certain verbiage can be employed in thedescription of the systems of the present invention, which is moreappropriate when defining a system. Thus, in another subembodiment thesystem comprises a dataset comprising the first and second subtypecut-points, and a second analytical unit upstream of the firstanalytical unit for determining the sequence and identity of subtypes inthe flow, wherein the central processing unit is further logicallyprogrammed to: (i) correlate the first subtype cut-point with the firstsubtype in sequence, and the second subtype cut-point with the secondsubtype in sequence; (ii) select the first subtype cut-point forcomparison to the measurements when the diversion valve is turned towardthe transmission pipe; and (iii) select the second subtype cut-point forcomparison when the diversion valve is turned toward the transmix pipe.

In another subembodiment, in which the flow further comprises a thirdsubtype in sequence, the dataset further comprises a third subtypecut-point, and the central processing unit is further logicallyprogrammed, after signaling the diversion valve to turn the flow towardthe transmission pipe in response to the measurements reaching thesecond subtype cut-point, to: (i) correlate the third subtype cut-pointwith the third subtype in sequence; (ii) select the second subtypecut-point for comparison to the measurements when the diversion valve isturned toward the transmission pipe; and (iii) select the third subtypecut-point for comparison when the diversion valve is turned toward thetransmix pipe.

Finally, it will be understood that a certification process can beimplemented downstream of the transmix valve to confirm that flowthrough the transmission pipe was not resumed too early. Certificationcould be achieved by sampling the flow one or more times after thetransmix valve is turned back toward the transmission pipe, andconfirming that none of the physical properties for the flow violate anyof the cut-points for the sub-type flowing through the valve.

Discussion of Depicted Embodiments

Reference is made to FIGS. 1 and 2 and the cut-points recited in Example1 for a better understanding of how the invention can be practiced. Itis to be understood that the drawings and this discussion are exemplaryof the methods and systems of the present invention, and not intended tolimit the scope of the invention as recited in the claims.

The invention includes providing pre-determined cut-points that ensurecompliance with common carrier pipeline specifications for hydrocarbonproducts shipped on the pipeline. Preferred specifications define theproduct by specific gravity, sulfur content, haze, and flash point. Whenthese cut-points are employed, the invention will encompass having anonline specific gravity monitor, online sulfur analyzer, online hazemeter monitor and online flash point analyzer. The invention will have asample point connection on the pipeline upstream of the pipelinemanifold to feed the product flowing in the pipeline to a sample productfast loop skid. The product fast loop skid will have a sample pump andmotor, sample conditioning equipment, solenoid valves to control flow ofthe product, back-check valves, flow metering, pressure transmitter andfilters. Upon product exiting the fast loop skid, product will bedistributed to an analyzer building. The building will contain a processflash point analyzer, sulfur analyzer and haze meter analyzer, andoptionally a specific gravity monitor.

The conditioning sample stream will flow by and into each of theindividual analyzers and return back to the pipeline completing thesample product fast loop. When the conditioning streams flow by eachanalyzer, tubing will connect the sample stream allowing product to flowto each analyzer. Each analyzer has a sample connection to the bypasssample stream. The test sample from each analyzer is fed into tubingthat flows to two sampling recovery tanks. The test sample stream iscontrolled by solenoid valves to direct the flow to one of two samplingrecovery tanks. One sampling recovery tank will be for gasoline andgasoline-diesel fuel transmix and the other sampling recovery tank willbe for diesel and diesel-jet fuel transmix.

The invention process preferably uses a Programmable Logic Controller(PLC) to control the motors, solenoid valves, analyzers, sample recoverytanks, and pumps. The PLC will also monitor pressure transmitters, meterflow transmitters, temperature transmitters, guided-wave radar levelinggauges on sample recovery tanks, hydrocarbon detectors, oxygendetectors, and all alarms for the invention.

The process flow has the PLC opening the solenoid valve to allow thesample stream to feed the product sample skid. The PLC will send asignal to start the sample skid pump and motor. On the sample skid, thePLC will monitor the flow of product from the pipeline through theCoriolis meter, will receive the specific gravity reading from theCoriolis meter monitor the pressure transmitter on the sample productline to make sure the pump has properly pressurized the sample line,control the sample product flow to each process analyzer, monitor eachanalyzer in order to receive test results, direct the test sample streamto the appropriate sampling recovery tank, and monitor the samplingstream flow back to pipeline. Downstream of each analyzer, the PLC willdirect the sample stream flow to the appropriate sample recovery tank,and monitor the inventory in each sample recovery tank. Once theinventory in a tank reaches a fixed level the PLC will also control whento pump the recovery tank volume back into the pipeline. This willensure the product in the pipeline is the appropriate product (matches)to pump from the sample recovery tank.

The analyzer building has a set of three process analyzers. The firstanalyzer is the flash point analyzer. This process analyzer will givetest results between 10-15 seconds. The PLC will control the analyzer toobtain a sample from the sampling condition product line. The resultsfrom the analysis are sent to the pipeline operator station to assist indetermining when to direct the flow in the pipeline to the appropriatestorage tank in the petroleum terminal. The timing to activate theanalyzer to take a sample will be controlled by the PLC. The PLC willmonitor information provided by the pipeline operator to determine whento activate the analyzer.

The second analyzer in the building is the sulfur analyzer. This processanalyzer will provide a test result between 10-15 seconds. The PLC willcontrol the analyzer to obtain a sample from the sampling conditionproduct line. The results from the test are sent to the pipelineoperator station to assist in determining when to direct the flow in thepipeline to the appropriate storage tank in the petroleum terminal. Thetiming to activate the analyzer to take a sample will be controlled bythe PLC. The PLC will monitor information provided by the pipelinecompany to determine when to activate the analyzer.

The third analyzer in the building is the haze meter analyzer. Thisprocess analyzer will provide a test result between 5-10 seconds. ThePLC will control the analyzer to take a sample from the samplingcondition product line. The results from the test are sent to thepipeline operator station to assist in determining when to direct theflow in the pipeline to the appropriate storage tank in the petroleumterminal. The timing to activate the analyzer to take a sample will becontrolled by the PLC. The PLC will monitor information provided by thepipeline company to determine when to activate the analyzer.

Near Infra-Red (NIR) Spectroscopy

NIR spectroscopy is an everyday tool used by the oil and gas industry.NIR does not require any specific sample preparation, requires shortacquisition time, and allows performing an online measurement in anon-intrusive way. This is critical for the oil and gas industry sincethe product, as crude oil or refined fuel, remains almost its entirelifetime in pipelines.

To perform an NIR online measurement there are two possibilities. Eitheran immersion probe or a flow cell is used. Immersion probes are mostwidely used for Fourier transform near infrared (FT-NIR) measurements inprocess control and can work in a transmission mode or a reflectiondepending on the transmittance of the sample. For crude oil, reflectancewill be typically used, while, for refined fuels, transmission can bethe most appropriate. Besides immersion probes, flow cells are widelyused. In this case, the sample flows directly through the cell where thespectrum is measured and measurement is done exclusively in transmissionmode. Typically, a flow cell probe allows one to acquire the spectra ofa fluid flowing in a pipeline at a high pressure, while the immersionprobe is designed to measure at pressures close to atmospheric.

A large number of properties are measured with NIR spectroscopy thesedays at refineries with the final goal of ensuring quality or optimizingthe production process. Those properties include, without limitation,RON (research octane number), MON (motor octane number), cetane index, %aromatics, % olefins, % benzene and % oxygenates, to RVP (Reid vaporpressure), D10%, D50%, D90%, Pour Point, Cloud Point, and Cold FilterPlugging Point or E170. Suitable NIR analyzers are the OMA 300 byApplied Analytical, having a spectral range of 400-1100 nm, ANALECT®PCM™ Series by Applied Instrument Technologies, having a spectral rangeof 833-8333 nm, the HP260X by ABB, having a spectral range of 714-2630nm, the XDS Process Analytics™ by FOSS NIR Systems Inc., having aspectral range of 800-2200 nm, and the PetroScan™ by Light TechnologyIndustries, Inc., having a spectral range of 1200-2400 nm.

Chemometrics

“Chemometrics” is a term applied to the generic discipline containingcomputers and mathematics to derive meaningful chemical information fromsamples of varying complexity (Workman, J. J., Jr (2008) NIRspectroscopy calibration basic. In: Burns, D. A. and Ciurczak, E. W.(eds), Handbook of Near-Infrared Analysis, 3rd edn. CRC Press, BocaRaton, Fla.). In chemometrics, a computer is tasked with interpretingNIR spectra from a plurality of samples using a variety of multivariatemathematical techniques. These techniques are used to produce amathematical calibration model.

In routine NIR analysis, the spectra should be pretreated to enhanceinformative signals of the interested components and reduceuninformative signals as much as possible (Pantoja PA et al.,Application of Near-Infrared Spectroscopy to the Characterization ofPetroleum, in Analytical Characterization Methods for Crude Oil andRelated Products, First Edition. Edited by Ashutosh K. Shukla. Published2018 by John Wiley & Sons Ltd.). Smoothing, multiplicative scattercorrection, mean centering, and Savitzky-Golay derivation are commonlyapplied to pretreat the spectra before modeling in order to remove thescattering effect created by diffuse reflectance and to decreasebaseline shift, overlapping peak, and other detrimental effects on thesignal-to-noise ratio (Boysworth, M. K. and Booksh, K. S. (2008) Aspectsof multivariate calibration applied to near-infrared spectroscopy. In:Burns, D. A. and Ciurczak, E. W. (eds), Handbook of Near-InfraredAnalysis, 3rd edn. CRC Press, Boca Raton, Fla.).

NIR spectra are ultimately calibrated to relate the observed spectra, ina predictive manner, to a property of interest. With calibration it ispossible to predict relevant physicochemical properties of an unknownhydrocarbon that compare accurately with reference information on theseproperties. In the process of this invention, the reference informationis generated from pipeline samples taken simultaneously with spectralinformation on the pipeline to generate a chemometric dataset. The maincalibration methods, as described by Lopez-Gejo et al., 2008, includeprincipal component analysis (PCA), partial least squares (PLS)regression, and artificial neural networks (ANNs) (Lopez-Gejo, J.,Pantoja, P. A., Falla, F. S., et al. (2008) Electronical and vibrationalspectroscopy. In: Petroleum Science Research Progress, Publisher, Inc.,187-233).

Thus, in one set of subembodiments one or more of the physical propertymeasurements is obtained by generating a spectral response of the firstor second hydrocarbon subtypes in the flow using absorption spectroscopywith a near infrared analyzer, and comparing the spectral response to achemometric dataset specific for the physical property of the first orsecond hydrocarbon subtypes.

In another set of subembodiments the chemometric dataset is built bytaking two or more samples of the first or second hydrocarbon subtypesfrom a pipeline; measuring the physical property of the samples offline;simultaneously with taking the two or more samples, obtaining a spectralresponse of the first or second hydrocarbon subtype in the pipelineusing absorption spectroscopy with a near infrared analyzer; andcorrelating the spectral response with the measured physical property ofthe samples.

EXAMPLES

In the following examples, efforts have been made to ensure accuracywith respect to numbers (e.g., amounts, temperature, etc.) but someerrors and deviations should be accounted for. The following examplesare put forth so as to provide those of ordinary skill in the art with acomplete disclosure and description of how the methods claimed hereinare made and evaluated, and are intended to be purely exemplary of theinvention and are not intended to limit the scope of what the inventorsregard as their invention.

Example 1 Exemplary Cut-Points

Table 1 provides exemplary physical property specifications for fourdifferent fuel types commonly transmitted on petroleum pipelines. Thespecifications themselves can be used as cut-points in the methods ofthe present invention, or values close to the specifications could alsobe selected depending on the pipeline's objectives. Thus, for example,if there are three sequential batches flowing through the transmissionpipe, jet fuel followed by gasoline followed by jet fuel, the CPU woulddivert the flow to the transmix pipe once any one of the followingconditions were satisfied:

specific gravity falls below 0.775; or

API gravity goes above 51

The CPU would divert the flow back to the transmission pipe once allthree of the following conditions were satisfied:

specific gravity falls below 0.770;

API gravity goes above 52; and

sulfur falls below 80 ppm

The CPU would divert the flow back to the transmix pipe when any of thefollowing conditions was satisfied:

specific gravity goes above 0.770;

API gravity goes below 52; or

sulfur goes above 80 ppm;

The CPU would divert the flow back to the transmission pipe once all ofthe following conditions were satisfied:

specific gravity goes above 0.775;

API gravity goes below 51; and

flash point goes above 38° C.

TABLE 1 Specific API Min Max Gravity Gravity FlashPoint Sulfur Jet Fuel.775-.840 51-37 38° C. 3,000 ppm Diesel Fuel .775-.840 51-37 52° C.   15ppm Gasoline .710-.770 68-52 —   80 ppm Diluent .600-.775 104-51  —2.000 ppm

Example 2 Interface Studies

A lab-scale pipeline simulation was undertaken to determine whether theanalyzing equipment selected for the invention could analyze arepresentative flow for sulfur with sufficient accuracy and frequency toidentify transmix interfaces between various subtypes of hydrocarbon,and to discriminate between the transmix and product types. Subtypeschosen for the studies were isopropyl alcohol, aviation turbine fuel,ultra-low sulfur diesel, gasoline, diluent, and new gasoline or dieselnot previously run through the system.

Sulfur measurements were taken every 10 or 15 seconds for all of thesimulations by a Sindie® 6010 On-line MWD XRF Analyzer from XOS®Products. Sulfur concentrations in the flow are plotted in FIGS. 3through 22 for all of the simulations. The batches transitioned from oneproduct type to another at different rates, depending on the volume oftransmix between the two batches, but the sulfur analysis was capable ofdiscriminating between adjacent product types and defining the transmixsegment between them based on sulfur concentration for most simulations.Sulfur was not able to discriminate between several batches because thesulfur content for these batches was so similar. See, e.g., FIGS. 14-16.For these batches, another cut-point would need to be employed toidentify the transmix segment and discriminate between the batches suchas gravity, flash point, haze or color.

Other Embodiments

Other embodiments of the invention will be apparent to those skilled inthe art from consideration of the specification and practice of theinvention disclosed herein. It is intended that the specification andexamples be considered as exemplary only, with a true scope and spiritof the invention being indicated by the following claims.

1) An automated method for reducing transmix production on a pipelinecomprising: a) providing a flow of hydrocarbon in a transmission pipecomprising first and second hydrocarbon subtypes in sequence separatedby transmix; b) providing a transmix pipe in fluid communication withthe transmission pipe separated from the transmission pipe by a transmixvalve under the control of a central processing unit; c) repeatedlyanalyzing the flow for physical property measurements; d) comparing, inthe central processing unit, the measurements to a first subtypecut-point, and diverting the flow to a transmix pipe when themeasurements reach the first subtype cut-point; and e) resuming the flowthrough the transmission pipe when the measurements reach a secondsubtype cut-point, wherein one or more of the physical propertymeasurements is obtained by generating a spectral response of the firstor second hydrocarbon subtypes in the flow using absorption spectroscopywith a near infrared analyzer, and comparing the spectral response to achemometric dataset specific for the physical property of the first orsecond hydrocarbon subtypes. 2) The method of claim 1 wherein thechemometric dataset is built by taking two or more samples of the firstor second hydrocarbon subtypes from a pipeline; measuring the physicalproperty of the samples offline; simultaneously with taking the two ormore samples, obtaining a spectral response of the first or secondhydrocarbon subtype in the pipeline using absorption spectroscopy with anear infrared analyzer; and correlating the spectral response with themeasured physical property of the samples. 3) An automated method forreducing transmix production on a pipeline comprising: a) providing aflow of hydrocarbon in a transmission pipe comprising first and secondhydrocarbon subtypes in sequence separated by transmix; b) providing atransmix pipe in fluid communication with the transmission pipeseparated from the transmission pipe by a transmix valve under thecontrol of a central processing unit; c) providing first and secondcut-points for different physical properties of the first subtype; d)providing first and second cut-points for different physical propertiesof the second subtype; e) repeatedly analyzing the flow for physicalproperty measurements; f) comparing, in the central processing unit, thephysical property measurements to the first and second cut-points of thefirst subtype, and diverting the flow to a transmix pipe when themeasurements reach the first or second cut-point of the first subtype;g) resuming the flow through the transmission pipe when the measurementsreach the first and second cut-points for the second subtype wherein oneor more of the physical property measurements is obtained by generatinga spectral response of the first or second hydrocarbon subtypes in theflow using absorption spectroscopy with a near infrared analyzer, andcomparing the spectral response to a chemometric dataset specific forthe physical property of the first or second hydrocarbon subtypes. 4)The method of claim 3 wherein the chemometric dataset is built by takingtwo or more samples of the first or second hydrocarbon subtypes from apipeline; measuring the physical property of the samples offline;simultaneously with taking the two or more samples, obtaining a spectralresponse of the first or second hydrocarbon subtype in the pipelineusing absorption spectroscopy with a near infrared analyzer; andcorrelating the spectral response with the measured physical property ofthe samples. 5) An automated method for reducing transmix production ona pipeline comprising: a) providing a flow of hydrocarbon in atransmission pipe comprising first and second hydrocarbon subtypes insequence separated by transmix; b) providing a transmix pipe in fluidcommunication with the transmission pipe separated from the transmissionpipe by a transmix valve under the control of a central processing unit;c) receiving a subtype sequence identification signal at the centralprocessing unit identifying the first and second subtypes and thelocation of the first and second subtypes in the transmission pipe; d)receiving physical property measurements of the flow passing through thevalve at the central processing unit; e) executing programmed logic inthe central processing unit to: i) determine the subtype flowing throughthe valve based on the subtype sequence identification signal; ii) whenthe first subtype is flowing through the valve, accessing a datasetcomprising a first cut-point for the first subtype and comparing thephysical property measurements to the first cut-point of the firstsubtype; iii) diverting the flow to the transmix pipe when a physicalproperty measurement reaches the first cut-point of the first subtype;iv) accessing a dataset comprising the first cut-point of the secondsubtype, comparing the physical property measurements to the firstcut-point of the second subtype; and v) resuming the flow through thetransmission pipe when a physical property measurement reaches the firstcut-point of the second subtype; wherein one or more of the physicalproperty measurements is obtained by generating a spectral response ofthe first or second hydrocarbon subtypes in the flow using absorptionspectroscopy with a near infrared analyzer, and comparing the spectralresponse to a chemometric dataset specific for the physical property ofthe first or second hydrocarbon subtypes. 6) The method of claim 5wherein the chemometric dataset is built by taking two or more samplesof the first or second hydrocarbon subtypes from a pipeline; measuringthe physical property of the samples offline; simultaneously with takingthe two or more samples, obtaining a spectral response of the first orsecond hydrocarbon subtype in the pipeline using absorption spectroscopywith a near infrared analyzer; and correlating the spectral responsewith the measured physical property of the samples. 7) The method ofclaim 1, further comprising: a) providing a second cut-point for thefirst subtype for a different physical property than the firstcut-point; b) providing a second cut-point for the second subtype for adifferent physical property than the first cut-point; c) diverting theflow to a transmix pipe when the flow reaches the first or secondcut-point of the first subtype; and d) resuming the flow through thetransmission pipe when the flow reaches the first and second cut-pointsof the second subtype. 8) The method of claim 7, further comprising: a)providing a third cut-point for the first subtype for a differentphysical property than the first and second cut-points; b) providing athird cut-point for the second subtype for a different physical propertythan the first and second cut-points; c) analyzing the flow for physicalproperty measurements of the first, second and third cut-points of thefirst and second subtypes; d) diverting the flow to the transmix pipewhen the physical property measurements reach the first or second orthird cut-point of the first sub-type; and e) resuming the flow throughthe transmission pipe when the physical property measurements reach thefirst and second and third cut-points of the second subtype. 9) Themethod of claim 1, wherein the flow of hydrocarbon further comprises athird subtype in sequence, further comprising: a) providing a firstcut-point for the third subtype; b) analyzing the flow for physicalproperty measurements of the first cut-point of the second subtype andthe first cut-point of the third subtype; c) diverting the flow to thetransmix pipe when physical property measurement reaches the firstcut-point of the second subtype; and d) resuming the flow through thetransmission pipe when the measurements reach the third subtype firstcut-point and third subtype second cut-point. 10) The method of claim 1wherein the flow comprises three or more hydrocarbon subtypes selectedfrom conventional gasoline, reformulated gasoline, diesel fuel,ultra-low sulfur diesel, biodiesel fuel, aviation turbine fuel, heatingoil, kerosene, RBOB, PBOB, CBOB, subgrade gasoline, diluent, propane,pentane and butane. 11) The method of claim 1 wherein the first subtypeis a high sulfur subtype and the second subtype is a low sulfur subtype,and the second subtype first cut-point comprises a sulfur content value.12) The method of claim 1 wherein the first subtype is a low sulfursubtype and the second subtype is a high sulfur subtype, and the firstsubtype first cut-point is a sulfur content value. 13) The method ofclaim 1 wherein the cut-points are physical property values selectedfrom sulfur content, specific gravity, haze and flashpoint. 14) Themethod of claim 1 wherein: a) physical properties are measured foraviation turbine fuels according to ASTM D1655 - 15d; b) physicalproperties are measured for diesel fuels according to ASTM D975-15c. 15)The method of claim 1 wherein the flow is analyzed for the firstcut-point of the first subtype at a frequency greater than once every 30seconds. 16) The method of claim 1 wherein the flow of hydrocarbon isanalyzed by: a) withdrawing a sample of the flow of hydrocarbon from thetransmission pipe; b) transmitting the sample to an analyzing unit; andc) either returning the sample to the transmission pipe, or transmittingthe sample to a storage unit. 17) The method of claim 1, whereinreaching a cut-point occurs when a physical property corresponding tothe cut-point is greater than or equal to the cut-point when thecut-point defines a ceiling. 18) The method of claim 1, wherein reachinga cut-point occurs when a physical property corresponding to thecut-point is less than or equal to the cut-point when the cut-pointdefines a floor. 19) The method of claim 1, wherein reaching a cut-pointoccurs when two or more consecutive analyses of the flow yield aphysical property measurement greater than or equal to the cut-pointwhen the cut-point defines a ceiling, and a physical propertymeasurement less than or equal to the cut-point when the cut-pointdefines a floor.